The present invention relates to nuclear magnetic resonance (NMR) borehole measurements and more particularly to fluid typing based on separation of signals from different fluids using user-adjusted measurement parameters.
The ability to differentiate between individual fluid types is one of the main concerns in the examination of the petrophysical properties of a geologic formation. For example, in the search for oil it is important to separate signals due to producible hydrocarbons from the signal contribution of brine, which is a fluid phase of little interest. Extremely valuable is also the capability to distinguish among different fluid types, in particular, among clay-bound water, capillary-bound water, movable water, gas, light oil, medium oil, and heavy oil. However, so far no approach has been advanced to reliably perform such fluid typing in all cases.
In evaluating the hydrocarbon production potential of a subsurface formation, the formation is described in terms of a set of xe2x80x9cpetrophysical properties.xe2x80x9d Such properties may include: (1) the lithology or the rock type, e.g., amount of sand, shale, limestone, or more detailed mineralogical description, (2) the porosity or fraction of the rock that is void or pore space, (3) the fluid saturations or fractions of the pore space occupied by oil, water and gas, and others. Various methods exist for performing measurements of petrophysical properties in a geologic formation. Nuclear magnetic resonance (NMR) logging, which is the focus of this invention, is among the best methods that have been developed for a rapid determination of such properties, which include formation porosity, composition of the formation fluid, the quantity of movable fluid and permeability, among others. At least in part this is due to the fact that NMR measurements are environmentally safe. Importantly, NMR logs differ from conventional neutron, density, sonic, and resistivity logs in that NMR logs are essentially unaffected by matrix mineralogy, i.e., provide information only on formation fluids. The reason is that NMR signals from the matrix decay too quickly to be detected by the current generation NMR logging tools. However, such tools are capable of directly measuring rock porosity filled with the fluids. Even more important is the unique capability of NMR tools, such as NUMAR""s MRIL(copyright) tool, to distinguish among different fluid types, in particular, clay-bound water, capillary-bound water, movable water, gas, light oil, medium oil, and heavy oil by applying different sets of user-adjusted measurement parameters.
To better appreciate how NMR logging can be used for fluid signal separation, it is first necessary to briefly examine the type of parameters that can be measured using NMR techniques. NMR logging is based on the observation that when an assembly of magnetic moments, such as those of hydrogen nuclei, are exposed to a static magnetic field they tend to align along the direction of the magnetic field, resulting in bulk magnetization. The rate at which equilibrium is established in such bulk magnetization upon provision of a static magnetic field is characterized by the parameter T1, known as the spin-lattice relaxation time. Another related and frequently used NMR logging parameter is the spin-spin relaxation time T2 (also known as transverse relaxation time), which is an expression of the relaxation due to non-homogeneities in the local magnetic field over the sensing volume of the logging tool. Both relaxation times provide information about the formation porosity, the composition and quantity of the formation fluid, and others.
Another measurement parameter obtained in NMR logging is the diffusion of fluids in the formation. Generally, diffusion refers to the motion of atoms in a gaseous or liquid state due to their thermal energy. Self-diffusion is inversely related to the viscosity of the fluid, which is a parameter of considerable importance in borehole surveys. In a uniform magnetic field, diffusion has little effect on the decay rate of the measured NMR echoes. In a gradient magnetic field, however, diffusion causes atoms to move from their original positions to new ones, which moves also cause these atoms to acquire different phase shifts compared to atoms that did not move. This effect contributes to a faster rate of relaxation in a gradient magnetic field.
NMR measurements of these and other parameters of the geologic formation can be done using, for example, the centralized MRIL(copyright) tool made by NUMAR, a Halliburton company, and the sidewall CMR tool made by Schlumberger. The MRIL(copyright) tool is described, for example, in U.S. Pat. No. 4,710,713 to Taicher et al. and in various other publications including: xe2x80x9cSpin Echo Magnetic Resonance Logging: Porosity and Free Fluid Index Determination,xe2x80x9d by Miller, Paltiel, Millen, Granot and Bouton, SPE 20561, 65th Annual Technical Conference of the SPE, New Orleans, La., Sep. 23-26, 1990; xe2x80x9cImproved Log Quality With a Dual-Frequency Pulsed NMR Tool,xe2x80x9d by Chandler, Drack, Miller and Prammer, SPE 28365, 69th Annual Technical Conference of the SPE, New Orleans, La., Sep. 25-28, 1994. Details of the structure and the use of the MRIL(copyright) tool, as well as the interpretation of various measurement parameters are also discussed in U.S. Pat. Nos. 4,717,876; 4,717,877; 4,717,878; 5,212,447; 5,280,243; 5,309,098; 5,412,320; 5,517,115, 5,557,200 and 5,696,448, all of which are commonly owned by the assignee of the present invention. The Schlumberger CMR tool is described, for example, in U.S. Pat. Nos. 5,055,787 and 5,055,788 to Kleinberg et al. and further in xe2x80x9cNovel NMR Apparatus for Investigating an External Sample,xe2x80x9d by Kleinberg, Sezginer and Griffin, J. Magn. Reson. 97, 466-485, 1992. The content of the above patents is hereby incorporated by reference; the content of the publications is incorporated by reference for background.
It has been observed that the mechanisms determining the measured values of T1, T2 and diffusion depend on the molecular dynamics of the formation being tested and on the types of fluids present. Thus, in bulk volume liquids, which typically are found in large pores of the formation, molecular dynamics is a function of both molecular size and inter-molecular interactions, which are different for each fluid. Water, gas and different types of oil each have different T1, T2 and diffusivity values. On the other hand, molecular dynamics in a heterogeneous media, such as a porous solid that contains liquid in its pores, differs significantly from the dynamics of the bulk liquid, and generally depends on the mechanism of interaction between the liquid and the pores of the solid media. It will thus be appreciated that a correct interpretation of the measured signals can provide valuable information relating to the types of fluids involved, the structure of the formation and other well-logging parameters of interest.
It should be clear that the quality of the fluid typing depends on the magnitudes of the contrasts between measurement signals from different fluid types. Generally, as the contrasts increase, the quality of the typing improves. Table 1 below shows the ranges of the characteristic parameters for brine, gas, and oil measured by an MRIL(copyright)xe2x80x94C tool under typical reservoir conditions (i.e., pressure (P) from 2,000 to 10,000 psi, and temperature (T) from 100 to 350xc2x0 F.). Table 2 shows typical parameter values for a Gulf of Mexico sandstone reservoir. The information in the tables clearly reveals a broad distribution for T1, T2, D, and hydrogen index (HI) that is used in accordance with the present invention in fluid typing.
Despite the existing contrasts, a problem encountered in standard NMR measurements is that in some cases signals from different fluid phases cannot be fully separated. For example, NMR signals due to brine, which is of no interest to oil production, cannot always be separated from signals due to producible hydrocarbons. The reason is that for a particular measurement parameter there is an overlap in the ranges of the measured signals from these fluids.
Several methods for acquiring and processing gradient NMR well log data have been proposed recently that enable the separation of different fluid types. These separation methods are based primarily on the existence of a T1 contrast and a diffusion contrast in NMR measurements of different fluid types. Specifically, a T1 contrast is due to the fact that light hydrocarbons have long T1 times, roughly 1 to 3 seconds, whereas T1 values longer than 1 second are unusual for water-wet rocks. In fact, typical T1""s are much shorter than 1 sec, due to the typical pore sizes encountered in sedimentary rocks, providing an even better contrast.
Diffusion in gradient magnetic fields provides a separate contrast mechanism applicable to T2 measurements that can be used to further separate the long T1 signal discussed above into its gas and oil components. In particular, at reservoir conditions the self-diffusion coefficient D0 of gases, such as methane, is at least 50 times larger than that of water and light oil, which leads to proportionately shorter T2 relaxation times associated with the gas. Since diffusion has no effect on the T1 measurements, the resulting diffusion contrast can be used to separate oil from gas.
The T1 and diffusion contrast mechanisms have been used to detect gas and separate fluid phases in what is known as the differential spectrum method (DSM) proposed first in 1995. There are several problems associated with prior art methods, such as DSM. For example, generally DSM requires a logging pass associated with relatively long wait times (TW approximately 10 sec) so that DSM-based logging is relatively slow. Further, the required T1 contrast may disappear in wells drilled with water-based mud, even if the reservoir contains light hydrocarbons. This can happen because water from the mud invades the big pores first, pushing out the oil and thus adding longer T2""s to the measurement spectrum. In such cases, DSM or standard NMR time domain analysis (TDA) methods have limited use either because there is no separation in the T2 domain, or because the two phases are too close and can not be picked robustly. Separation problems similar to the one described above can also occur in carbonate rocks. In carbonates an overlap between the brine and hydrocarbons phases is likely because the surface relaxivity in carbonates is approximately ⅓ that of sandstones. In other words, for the same pore size, he surface relaxation in carbonates is about 3 times longer than that for a sandstone, such weak surface relaxation causing an overlap between the observable fluid phases. Additional problem for carbonates is the presence of vugs. Water bearing vugs, because of heir large pore sizes, have long T2""s and can easily be interpreted as oil by prior art techniques. No single technique seems to solve these and other problems encountered in standard logging practice.
It is apparent, therefore, that there is a need for a flexible apparatus and methods, using different contrast mechanisms, in which these and other problems associated with fluid typing in the prior art are obviated.
The present invention is based on using a combination of several different contrast mechanisms in NMR fluid typing measurements of a geologic formation. To this end, in accordance with the present invention, dependent on the specifics of the geologic formation the measurement tool uses different sets of NMR measurement parameters so as to select the optimum contrast mechanism for fluid typing. The contrast mechanisms used in a preferred embodiment include T1, T2, D, HI, and viscosity xcex7 contrasts, which are fundamental to fluid typing. In a preferred embodiment, the present invention uses Numar Corporation""s MRIL(copyright) tool because of its capability to make multi-contrast measurements. Appropriate selection of pulse sequences, such as CPMG, and acquisition parameters, such as pulse waiting time (TW ) and echo spacing time (TE), allows the acquisition of weighted spin echo data with different contrasts.
In particular, in accordance with a preferred embodiment, a method for fluid typing of a geological environment is disclosed, using nuclear magnetic resonance (NMR) measurements. The method comprises: determining a set of parameters for a gradient NMR measurement, obtaining a pulsed NMR log using the determined set of parameters; and selecting from the NMR log an optimum contrast mechanism and corresponding measurement parameters for fluid typing of the geological environment. In a preferred embodiment, the set of determined parameters comprises the interecho spacing TE of a pulsed NMR sequence, the magnetic field gradient G and the wait time TW of the NMR measurement. Further, in a preferred embodiment, the optimum contrast mechanism used in the method is based on diffusion, relaxation or hydrogen index contrast.
In another aspect of this invention, a method for fluid typing of a geological environment is disclosed using nuclear magnetic resonance (NMR) measurements, where the method comprises: conducting a first NMR measurement using a first predetermined set of measurement parameters; comparing the first NMR measurement results to a predetermined set of criteria applicable for different fluid types to estimate candidate types of fluids that may have produced the first NMR measurement results; selecting an appropriate type of contrast mechanism and a corresponding second set measurement parameters for the estimated types of fluids; and conducting a second NMR measurement using the second set of parameters to increase the accuracy of the fluid typing determination in case the second set of parameters is different from said first set of parameters. In a preferred embodiment, the first and the second set of parameters correspond to one or more of the DSM, EDM, SSM, TPM, and ICAM fluid typing methods, as described below.
In another aspect, the present invention is directed to a computer storage medium storing a software program to be executed on a computer, comprising: a first software application for capturing NMR data concerning a first measurement; a second software application, for comparing the first measurement data to pre-set rules determining the optimum contrast mechanism for use in the environment; and a third software application, for providing a predetermined set of measurement parameters according to the determined optimum contrast mechanism.
In another aspect, the present invention is an apparatus for fluid typing of a geological environment using nuclear magnetic resonance (NMR) measurements comprising: a logging tool capable of conducting NMR measurements in a borehole; data storage for storing NMR log data corresponding to one or more NMR measurements each measurement using a predetermined set of measurement parameters; a computer processor configured to execute a software application program for selecting from NMR log data an optimum contrast mechanism and corresponding measurement parameters for fluid typing of the geological environment; and a measurement cycle controller providing control signals to the logging tool for conducting NMR measurements based on input from said processor. In a preferred embodiment, the apparatus comprises a display for indicating the selection of measurement parameters to a human operator, and the logging tool has a dual wait-time sequencing capability.